Economics : Type Curve

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Utica Shale Condensate Window Type Curves Condensate Type Curve Assumptions(1) West East Single Well Economics(1) Lateral Length 8,000 8,000 80% Well Cost (MM) 7.7 7.7 Well Cost ( per foot) 962 964 60% IRRs % Total EUR (Bcfe / 1,000) 0.7 1.0 40% 31% Total EUR (Bcfe) 5.7 8.1 21% % Gas 42% 56% 20% 12% 27% 19% Assumed Well Spacing (ft) 600 600 10% Gross Undeveloped Locations(2) 129 73 0% Gas 2.50 / Oil 45.00 Gas 2.75 / Oil 50.00 Gas 3.00 / Oil 55.00 Gas 3.25 / Oil 60.00 Net Undeveloped Locations 97 54 Condensate West Condensate East Condensate Type Curves(1) 7,000 4.0 6,000 3.5 3.0 5,000 Mcfe per day 2.5 4,000 Bcfe 2.0 3,000 1.5 2,000 1.0 1,000 0.5 - 0.0 Months 0.7 Bcfe / 1,000' Daily Production 1.0 Bcfe / 1,000' Daily Production 0.7 Bcfe / 1,000' Cumulative Production 1.0 Bcfe / 1,000' Cumulative Production Note: See appendix slide 26 for detailed assumptions used to generate single well IRRs. 1. Assumes ethane rejection. 2. Assumes net undeveloped locations grossed up from 75% working interest WWW.GULFPORTENERGY.COM 27
Gulfport Energy Corp.
May 2018

May 2018 2018 Utica Dry Gas Type Curve Accelerates Returns Detailed engineering analysis supports moving to a more accelerated dry gas production profile, increasing type curve returns while maintaining EUR New Production Profile in 2018 Cumulative Gas Production1 Gen 3 Utica Dry Gas wells were produced above 2017 Type Curve 20 2017 wells and showed no reduction in EURs due to higher rates 2018 Dry Gas Type Curve (2.2 BCF/1,000') 2017 Dry Gas Type Curve (2.2 BCF/1,000') Cumulative Gas (Bcf) 15 2018 Utica Dry Gas wells will target initial production rates up to 40% above 2017 Type Curve with unchanged estimated EURs 10 Accelerated Production Curve is expected to significantly improve well IRRs by twelve percentage points from 72% to 84% due to 5 more immediate cash flow2 Backwardated strip intensifies this impact 0 0 6 12 18 24 Assessing viability of concept in Condensate areas Months on Production Accelerated Dry Gas Type Curve2 Acceleration Effect on EUR Daily Gas Production1 110% 2.5 IRR 45 2018 Accelerated Dry Gas Type 100% Payout 40 Curve 2017 TC 35 2017 Dry Gas Type Curve Gas EUR/1,000 (BCF) 90% Gas Rate (MMcf/Day) 2.0 Payout (Years) 30 80% 2018 TC IRR 25 70% 20 1.5 2018 TC 60% 15 2017 TC 50% 10 40% 1.0 5 15 25 35 45 55 0 20 25 30 35 40 45 0 6 12 18 24 Plateau Rate at 16,000' Lateral Length (MMcf/d) Gas IP Rate Normalized to 16,000 Lateral Months on Production (MMcf/d) 1 Production normalized to 16,000. 2 Based on 3.00 gas pricing; type curves do not represent proved reserves. 28
Eclipse Resources Corp.
May 2018

LOWER MARCELLUS DRIVING MORE VALUE PA Average Cumulative Gas per Well 5.0 Average Cumulative Gas per Well (bcf) 4.5 16 4.0 15 17 3.5 14 3.0 2.5 13 < 13 2.0 1.5 1.0 0.5 0.0 0 2 4 6 8 10 12 Month Game changing Stacked pay Longer laterals and Upper Marcellus, Lower Marcellus enhanced completions and Utica potential Scotia Howard Weil 2018 Energy Conference 12
Chesapeake Energy Corp
March 2018

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